An Introduction to Britain’s Capacity Market


Britain’s “capacity market” is the current mechanism designed to ensure that “the lights stay on”: that we have enough electricity supply to meet our highest levels at demand, and that this supply is guaranteed to be available when it’s needed.

As I write this, it’s the second week of February 2018. Great Britain’s “Electricity Market Reform Delivery Body” has just announced that the latest “T4” capacity market auction, for delivery in 2021/2022, has cleared at a price of £8.40/kW/yr.

This article is intended as a primer for those who:

1. Are wondering what on earth that last sentence even meant!

or

2. Want some market context around the capacity market and Britain’s supply options.

Britain isn’t the only place to operate a capacity market. So even if you aren’t from there, you may still find this a useful read.

 

Guaranteeing capacity

Britain’s capacity market has a clear purpose: to sign contracts with companies who will (when all their individual contracts are added together) guarantee that enough supply of power will exist to meet demand at any time during a specific future period. It is up to National Grid, Britain’s system operator, to forecast future demand and hence decide what amount of supply needs to be contracted in each period.

Here in Britain, the period that matters is the winter, when long nights and cold temperatures lead to the highest levels of demand. This demand peaks early in the evening, between 5pm and 6pm. In recent years, the maximum levels of demand have reached just above 50GW.

In order to cover unforeseen events such as demand spikes or power plant breakdowns, National Grid wants to guarantee that there will be available generating capacity at some margin above this demand. For example, contracting to guarantee 55GW of supply would ensure a margin of around 10% above expected peak demand, enough for everyone to breathe easily.

In getting a contract, a power generator knows they will be paid on the basis that they will ensure a certain amount of capacity (kW) is guaranteed to be available. Hence the value of a contract is expressed as £/kW/yr.

At the recent rate of £8.40/kW/yr that means a 10MW generator with a capacity market contract will earn £8.40 x 10,000kW = £84,000 for each year of the contract. That revenue will be earned even if the generator never needs to be called on, so it’s a nice fixed revenue for the contract holder. In most cases (as we’ll see), these contracts are won by existing power plants. In this case, revenue from the capacity market is additional to whatever revenue they earn from their day-to-day energy (MWh) sales.

It’s worth stressing the units here. The capacity market is not about supplying an amount of energy, MWh, over a period of time. It’s about committing to supply power – MW, energy at the right rate – at any specific moment in time.

For the system operator, capacity market costs are an insurance premium for ensuring that, even in the most unlikely scenarios, the lights will stay on. In addition to sources of power generating capacity, demand-side response (DSR) is also eligible to enter the auction: after all, guaranteeing to reduce demand by a certain amount reduces the need to provide supply (and may be more cost-effective). Discharging storage capacity also counts, so long as the storage facility can be certain it will be charged up and ready, whenever the call to provide its contracted capacity might arrive. If you sign a contract and then fail to meet your commitment, the penalties are hefty!

The use of an auction – one where contract winners are the lowest bidders – is designed to arrive at the cheapest way to guarantee capacity availability. Ultimately these costs are, of course, passed on to electricity consumers.

The most recent auction price of £8.40/kW/yr applies to a total contracted capacity of 50.4GW. Multiply that up and it amounts to a total cost of £423m to guarantee that capacity for one year: or about £15 per household.

 

Terminology alert! (T4 vs T1)

Britain’s capacity market has actually had two auctions in the last two weeks. The first of these was what is termed a “T1” auction, the second a “T4”. In both cases the purpose of the auction was the same: to sign contracts to guarantee that enough supply of power will exist to meet demand over a specific future period. It’s quite possible the workings of the capacity market will change in future, but I’ll describe how it is just now.

The difference between T4 and T1 is how far into the future they look.

T4 auctions are designed to guarantee that predicted levels of demand can be met not today, but four years hence. Thus the T4 auction that happened last week was set up to contract guarantees of capacity availability for winter in four years’ time: 2021/2022. There have been three previous T4 auctions, set up to ensure availability of supply to meet peak demand in the winters of 2018/2019, 2019/2020 and 2020/2021.

If T4 relates to four winters ahead, by now you’ve hopefully guessed that T1 auctions are about more short-term capacity: one winter ahead. Thus the recent T1 auction was set up to contract guarantees of capacity for next winter, 2018/2019. That was the first of these short-term auctions.

The capacity contracted in a T1 auction is additional to capacity previously guaranteed in a T4 auction for the same winter period. Earlier, more forward-looking T4 auctions are designed to secure the majority of the projected capacity need. The T1 auction provided a closer-to-the-time top-up.

So in 2014, there was a T4 auction which secured just over 49GW of capacity for next winter, 2018/2019. The recent T1 auction covered next winter too and contracted a further 5.8GW of capacity. Together this means that next winter Britain has just under 55GW of total capacity that has signed contracts guaranteeing to provide power when needed – a nice margin above the likely peak demand.

Most capacity market contracts are just one-year in length, covering just the single future winter period they are targeted at. However each T4 auction has also included a small proportion of longer contracts, up to fifteen years.

For example last week’s T4 auction for 2021/2022 included just over 600MW of capacity which will be contracted not just for the winter of 2021/2022, but all the way through to the winter of 2035/2036. These longer contracts are particularly helpful where the capacity is going to be provided from a new-build project, not an existing power plant. After all, long contracts with known cash flows are very helpful in raising finance.

In total then, the capacity guaranteed for some future winter may have been secured in any of these three ways:

  1. The bulk of capacity secured four years ago, in a T4 auction (mainly one-year contracts, covering just that one winter)
  2. A smaller amount of capacity secured more than four years ago, in a previous T4 auction primarily designed for an earlier winter, but where those T4 contracts were longer in length, covering multiple winters, including the one in question.
  3. A smaller amount of capacity secured a year ago, in a T1 auction (one-year contracts, covering just that one winter)

Here’s a chart from National Grid to illustrate this stacking of capacity. The years along the x-axis are the “delivery” years: so 2017 refers to the winter of 2017/2018 and so on. The T4 auctions to secure capacity in these delivery years will have taken place four years prior.

 

Figure 1: Britain’s secured future capacity, as of February 2018 (image source: National Grid)

 

(Note that 2017, the first year that the capacity market operated, was just based on a single auction with one-year-only contracts; the T4, T1 terminology and longer contracting only kicked in after that).

 

Britain’s winter peak demand mix, and its capacity market mix

To put the capacity market into context, it’s worth a quick look at Britain’s current electricity mix at peak times, along with the sources of supply which have been winning capacity market contracts for future years.

The chart below shows the sources which were providing power at the specific time of peak demand on each day in January 2018. On every one of these days, that time of peak demand was somewhere between 5.10pm and 5.50pm. The y-axis unit is MW and the data is from the “gridwatch” website. The numbers along the x-axis refer to the date (January 1st to 31st).

 

Figure 2: Electricity mix (MW) at times of peak demand, January 2018 (data: Gridwatch, analysis: Grey Cells Energy)

 

Nuclear, hydro, imports, pumped storage and biomass are fairly consistent. Unsurprisingly wind, at the top, is rather variable.

Coal in Britain is disappearing in summer, but is always present at peak times on these January evenings, though in varying amounts. Some weekends, when peak demand is low and coincides with strong winds (such as Jan 27th & 28th), coal is almost squeezed out. On other days, when demand is high but the weather calm (such as Jan 10th & 11th), coal is a significant contributor to the electricity mix at peak times. Throughout, it is combined cycle gas that contributes the most to meeting peak power requirements (gas, of course, is able to adjust up and down more flexibly).

On most days, wind was actually a significant contributor to Britain’s peak demand. However January 10th & 11th show why it can’t be relied upon to guarantee capacity when it’s most needed. You won’t see wind farm operators entering capacity market auctions. (Perhaps in future, if wind farms add battery or other storage to control their output, this may change). The growth of wind, squeezing out other sources much of the time, but unable to guarantee supply all the time, is a major reason why a capacity market exists.

The next chart picks out three calm days – January 10th, 11th and 26th – and then compares the power mix at peak demand on those days with the capacity market mix contracted for 2021/22. The latter incorporates last week’s T4 auction results, added to capacity previously secured on multi-year contracts in earlier T4 auctions (as per Figure 1):

 

Figure 3: Three calm days in January 2018 (fuel mix at peak demand and future capacity market comparison); data from gridwatch and National Grid, analysis by Grey Cells Energy

 

Existing Generators

Looking from the bottom up, in the main the capacity market stack looks pretty much the same as the current generation stacks on these windless days. That shouldn’t be too surprising given the fact that existing generators and interconnectors (for imports) won 90% of the contracts in the latest T4 auction, on which most of this capacity is based (the dark blue column for 2021 in figure 1). In the capacity market as in current generation, Britain depends mainly on gas.

That’s been one criticism made of Britain’s capacity market: that it awards an additional revenue stream to generators which are there anyway. Bear in mind though that this isn’t about generators which are there now, it’s about guaranteeing that sufficient generators will still be there in future (in this case four years ahead). Without the security of this future revenue stream there is a risk that some conventional generators, which are increasingly losing market share to renewable sources such as solar and wind, may not be there in future. Indeed failing to win a contract last week was the trigger for one coal plant to announce its decision to close. Given Britain’s policy to phase out coal, that’s no great problem. However, as that last chart shows, if the business case for gas plants started going the same way anytime soon, there would be a serious capacity risk.

A few other features stand out.

Imports

One is the increase in imports: 2.2GW of new interconnector capacity was a winner in this recent auction. In many cases better connected power systems will certainly provide a cheaper solution to reliability than will building new power plants. On the other, how does a dependence on external capacity to guarantee your own system fit with notions of domestic “energy security”?

DSR & Batteries

Included near the top of the capacity market stack are two relatively small contributions: from demand response (DSR) and non-hydro storage (mainly batteries). In the most recent auction, DSR won contracts for just under 1.2GW of capacity, a sizeable amount.

For batteries, there was much excitement when, in 2016, they won 500MW of capacity market contracts for the winter of 2020/2021 (when the auction price cleared much higher, at £22.5/kW/yr). Many of these were long-duration (15-year) contracts.

However the lower price for the 2021/2022 auction, along with changes to the market rules to discourage participation by batteries only able to discharge for short times, reduced this to just over 150MW. Although I and others are bullish on the long-term impact of batteries on Britain’s power system, at the moment it’s fair to say that batteries are not the cheapest way to provide this particular “demand peak” capacity guarantee service.

Small, flexible fossil-fuelled generators

Finally, you’ll notice a sizeable dark grey stripe which I’ve labelled “fossil (small and ocgt)”. Grouped in here are a sizeable number of fossil-fuelled projects. These are largely small in their individual capacities but numerous enough to add up to a big chunk of the market. In particular most of them consist of small-scale generator sets and “reciprocating engines”. Many are gas powered, but there is a sizeable quantity of diesel generation in here too. Some are CHP (combined heat and power) units, not just electricity generators.

Individually, these generators are often just a few MW or tens of MW in scale. They can be quickly and flexibly sited and are able to survive on a diet of infrequent usage (for example operating in short-term balancing markets in addition to the capacity market).

The growth of this sector has been another source of criticism of the capacity market outcomes, drawing newspaper headlines such as “dirty diesel generators in line for government subsidies” (e.g. here). On one hand this is true: after all, diesel generators are by no means “clean” energy so why provide them with another nice revenue stream, pushing cost onto consumers?

On the other it’s worth remembering what the capacity market is all about: guaranteeing capacity at least cost to energy consumers. Even aside from the fact that these small units are clearly competitive with respect to the latter, it’s worth remembering that winning capacity market contracts doesn’t mean that these generators will run for any significant time. Comparing the size of the capacity market stack with the supply mixes we see on the days shown, we can see that demand will almost always be met by the generating sources listed below these units. They largely provide a safety margin above the peak demand actually experienced.

Remember also that the capacity contract is about being there if needed. It’s an insurance policy for power at specific points in time. It’s not about generating additional amounts of energy over substantive time periods. If the availability of these small, flexible units to cover small amounts of capacity on rare days like January 10th allows the integration of larger quantities of renewable power, then the clean electricity the latter generates on other days will hugely outweigh any emissions from the brief use of “dirty diesel” (or gas). So while they may not be everyone’s preferred, long-term solution (including mine), these small, very flexible generating units are likely a “necessary evil” for the foreseeable future.

 

When capacity is more than enough

To further illustrate that point, bear in mind that the last chart picked on three “worst-case” days: ones with high demand and little wind. For most of January, when the wind was blowing, the capacity we’ve guaranteed via the capacity market looks like overkill; and those “dirty diesels” certainly won’t get a look in (Fig 4). And bear in mind too that there is plenty of time before 2021/2022 to contract additional capacity for that winter through a future auction, for example a T1.

Here are three windy days, January 17th, 23rd and 28th. There’s certainly no capacity shortage here!

 

Figure 4: Three windy days in January 2018 (fuel mix at peak demand and future capacity market comparison); data from gridwatch and National Grid, analysis by Grey Cells Energy

 

Concluding Notes:

Capacity markets in Britain and elsewhere are likely to be growing features of electricity market policy – not least to ensure that the growth of renewable power sources is balanced with the need to provide system reliability, even in the most unlikely scenarios of supply availability and demand.

Britain’s market is now a few years old, but its rules and processes will certainly evolve and be tweaked as time goes by. There will continue to be both opportunities and risks in building business cases based on future capacity market revenues. The economics which determine its outcomes will continue to change. I’ve also hinted at some of the objections that have been raised in respect of its outcomes (dirty diesel, subsidising existing plants and so on) – these too may lead to policy changes.

Regardless of the future of the capacity market, I hope this article has given you an insight into some of the current variables at play, the debates that arise and the fundamental electricity mix issues that the capacity market is aiming to address.

 

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